Q122 Gas Lock Event

Executive Summary

The Q-122 ESP well experienced two unplanned shutdown events that would typically escalate to mechanical intervention. Through IPOS-led real-time diagnosis and controlled operational response, an unnecessary ESP pull was avoided, and the well was returned to stable operation without mechanical intervention.

Root-cause analysis confirmed gas interference leading to gas lock within the ESP, not intake plugging or equipment failure. This conclusion was validated by repeatable underload behaviour, collapse and recovery of pump head, motor temperature response, and immediate reversibility with operational adjustment.

As a result, approximately USD 180k–360k in deferred production was preserved, and ESP pull risk (USD 300k–500k exposure) was eliminated. The ESP string and well integrity were maintained, and decision time was reduced from days to hours.

This case demonstrates the value of IPOS and NovoAlfa in enabling rapid, evidence-based decisions that protect production, avoid capital-intensive interventions, and shift ESP operations from reactive response to proactive control.

Financial Impact & IPOS Value Delivered

Baseline Context

Without real-time diagnostic clarity, ESP shutdowns of this nature in the Waha fields typically require 3-5 days for troubleshooting, decision alignment, and field execution, with material risk of escalation toward mechanical intervention.

In this case:

• Actual downtime: ~27 hours per event
• Typical downtime without diagnostic certainty: 3–5 days
• Net downtime avoided per event: ~2–4 days

Deferred Production Preserved

• Stabilized well test rate: 585 BOPD
• Oil price assumption: ~USD 75/bbl
• Daily gross revenue ≈ USD 43,875

Per Shutdown Event

2–4 days avoided = ~USD 90k–180k preserved

Two Shutdown Events

Total preserved production value:

≈ USD 180k–360k

This reflects production preservation only and excludes capital avoidance.

ESP Pull Risk Elimination (Capital Protection)

Absent confirmed hydraulic diagnosis (gas lock), repeated shutdown behaviour of this nature typically escalates to a precautionary ESP pull decision.

A standard ESP pull campaign in the Waha fields typically includes:

• Rig or workover mobilization
• ESP retrieval and inspection
• Pump/motor repair or replacement
• Additional deferred production during intervention

Indicative cost exposure:
USD 300k–500k per intervention (conservative range)

Through IPOS-led diagnosis and NovoAlfa execution, mechanical intervention was avoided and the installed ESP string preserved.

Portfolio Illustration (5 Comparable Wells)

If similar real-time diagnostic response is applied to 5 comparable ESP wells experiencing similar gas-lock shutdown behaviour:

Estimated production value preserved: ≈ USD 0.9–1.8 million

Assumptions:

• ~USD 90k–180k preserved per shutdown event
• Two comparable shutdown events per well (consistent with cyclic gas-lock behaviour)
• Comparable rates and downtime profiles
• Production impact only (excludes capital avoidance)

Executive Value Summary

Diagnostic Narrative – Q122 ESP Shutdown Events

Event

Q-122 experienced two unplanned ESP shutdown events characterized by loss of flow to surface. Each event was preceded by declining pump performance, underload conditions, and rising motor temperature, ultimately resulting in automatic shutdown on high motor temperature.

Feb 10 – Surface Boundary Change (Context)

Field data indicates WHP of ~450 psi versus ~600 psi at the last well test. During this period, PIP and PDP dropped simultaneously while ΔP remained essentially constant and motor current increased slightly. This behavior is consistent with a surface boundary condition change (WHP reduction), not pump hydraulic failure. This event is considered a triggering condition, separate from the subsequent gas-lock shutdown behavior.

Signal

The following repeatable signals were observed across both events:

• Pump differential pressure (ΔP) collapsed, indicating loss of developed head.
• Motor current dropped to sustained idle amps, confirming underload.
• Motor temperature increased progressively due to loss of effective cooling.
• Pump intake pressure (PIP) behavior was consistent with loss of liquid seal rather than intake restriction.

Upon restart or frequency increase:

• PDP recovered immediately
• Motor amps increased and exited idle
• Motor temperature decreased
• Drawdown improved as PIP trended downward

This pattern was consistent and repeatable across shutdown and recovery cycles.

Interpretation

The observed combination of underload, rising motor temperature, and reversible recovery with frequency increase indicates loss of liquid seal inside the pump stages due to free gas accumulation. Gas interference progressively reduced effective hydraulic work and motor cooling, leading to gas lock and shutdown.

The rapid restoration of pump head, motor load, and thermal stability following frequency increase confirms that the condition was hydraulic and reversible, consistent with gas-bound behavior rather than mechanical or solids-related restriction.

Conclusion

The ESP shutdown events on Q-122 were caused by gas interference leading to gas lock within the pump.

Intake plugging was evaluated and excluded. A solids-related restriction would be expected to produce increased hydraulic loading, non-reversible behavior, and limited recovery with frequency increase, none of which were observed. The consistent recovery of head, load, and drawdown confirms gas lock as the sole root cause.

Supporting Figures

Figures 1-3 provide supporting pressure, load, temperature, and recovery trends consistent with the diagnostic narrative above.

Recurring Gas-Lock Pattern

A consistent and repeatable operating pattern was observed:

• Motor current dropped to sustained idle amps (underload condition).
• Pump differential pressure (ΔP) progressively collapsed, indicating loss of developed head.
• Motor temperature increased due to reduced hydraulic cooling.
• The well shut down on high motor temperature.

Upon restart at 49 Hz:

• PDP immediately recovered,
• Motor amps increased and exited idle,
• Motor temperature decreased,
• Drawdown improved as PIP trended downward.

This cycle repeated consistently.

This reversible underload–thermal–recovery sequence confirms gas interference leading to gas lock. A solids-related intake restriction would present increased hydraulic loading and non-reversible behavior, which were not observed.

Exclusion of Intake Plugging

The observed behavior is characterized by sustained underload (idle motor current), progressive motor temperature increase due to loss of effective cooling, and consistent recovery following frequency increase. Recovery is marked by restoration of discharge pressure, motor load exiting idle, temperature reduction, and improved drawdown. This reversible hydraulic response is consistent with gas-bound recovery and regaining of liquid seal within the pump. A solids-related intake restriction would be expected to produce increased hydraulic loading and non-reversible behavior, which were not observed.

Conclusion

Frequency increase resulted in immediate recovery of discharge pressure and motor load with improved drawdown, confirming reversible gas-bound behavior and excluding mechanical intake restriction.

Well Model Confirmation (PROSPER)

A matched PROSPER model using the latest well test (31 Jan 2026) confirms that:

• Reduction in WHP leads to lower PIP and increased gas liberation at pump intake
• At lower intake pressure, free gas fraction increases, increasing risk of gas interference.
• Frequency sensitivity demonstrates that increasing HZ increases developed head and restores hydraulic performance.

The modeled sensitivities align with the observed field behavior during shutdown and recovery cycles.

The model therefore supports gas interference leading to gas lock as the root cause.

Event Timeline and Field Actions

ESP Configuration and Response

The ESP experienced reduced developed head due to gas accumulation within the pump stages. The installed gas-handling ESP configuration incorporates vortex crown stages designed to mitigate gas interference by promoting gas–liquid separation. Under elevated gas conditions, this configuration delays but does not fully eliminate gas lock, consistent with the observed transient loss and recovery of pump head.

When the free gas fraction becomes dominant within the pump stages, effective liquid continuity is lost. Under these conditions, affected stages are unable to generate sufficient hydraulic head, resulting in a sharp reduction in discharge pressure and, in severe cases, gas lock.

Conclusions & Operational Recommendations

Confirmed Root Cause

The Q-122 shutdown events were caused by cyclic gas interference leading to gas lock. Intake plugging and mechanical failure were excluded based on reversible hydraulic behaviour and real-time diagnostics.

Mandatory Operating Envelope (Derived from Case)

• Maintain WHP ≥ 450 psig to limit gas breakout at pump intake.
• Avoid aggressive choke openings or rapid surface pressure reductions that increase GVF risk.

Control Strategy (Prevent Recurrence)

• Apply PID control mode to stabilize intake and discharge pressures.
• Minimize rapid frequency changes and surface pressure fluctuations that destabilize pump hydraulics.

Monitoring & Response Protocol (Proven Effective)

Continuously monitor:

• Motor current (underload / idle behaviour)
• Pump discharge pressure (PDP stability)
• WHP deviations
• Motor temperature rise rate

If cyclic behaviour reappears:

• Execute a controlled shut-in.
• Perform gradual casing bleed-off prior to restart.
• Resume operation under close real-time surveillance.

Outcome & Value Implication

This operating and response strategy restored stable production on Q-122, eliminated ESP pull risk, and preserved USD 180k–360k in production across two shutdown events, while avoiding USD 300k–500k of ESP pull exposure. Decision time was reduced from days to hours.

Maintaining the defined operating envelope and response protocol is therefore not only an operational requirement, but a capital and production risk control measure. Deviation from these controls materially increases exposure to deferred production and unnecessary mechanical intervention.